Generally, naturally occurring hydrocarbons exist under pressure underground and are extracted at pressure via wells, but the well streams contain, in addition to hydrocarbons, water and solids. Moreover, there is generally present in the hydrocarbons dissolved methane, ethane and propane and heavier gases in addition to the possible presence of one or more normally gaseous components such as nitrogen, helium, carbon dioxide and hydrogen sulphide.
In remote locations on land, all or part of the above gases must be removed to produce a liquid which is pumpable and readily stabilized to produce a crude oil suitable for ultimate transport at atmospheric pressure by road or sea tanker.
In off-shore locations where the loading of tankers from production platforms is envisaged, a substantial part of the above gases must be removed in order to produce a shippable crude liquid capable of being safely transported at or near atmospheric pressure in the tanks of a ship
For off-shore locations with oil pipelines and for other locations it may be desirable to produce a crude having a finite vapor pressure above atmospheric but it is nevertheless desirable to recover the maximum amount of the well head stream in the liquid phase.
There are many process options possible for the gas/liquid separation and it is possible by flash separation of the mixture and treatment of the recovered gases by distillation at low temperature and/or high pressure with the use of an oil wash to make a very good separation between the C.sub.1 and C.sub.2 or C.sub.2 and C.sub.3 or C.sub.3 and C.sub.4 fractions and by remixing of the crude from the flash separation with the separated and recovered liquids from the gas fractions to extract the maximum possible percentage of light fractions for inclusion in the recovered liquid phase without exceeding a given vapor pressure for a given temperature of the liquid. However, the above distillation procedures require complex and bulky processing equipment and would normally require the inclusion of a fired heater and at least one and possibly more distillation columns. Such equipment is not suitable for remote locations or for the limited space and load carrying capacity of off-shore platforms.
Generally, naturally occurring hydrocarbons are separated at or near the well head in gas/oil separator units which usually consist of one or more flash separation stages. FIG. 1 of the accompanying drawings shows a schematic arrangement of a typical gas oil separator containing three separator stages 2, 4, 6, and in which well stream fluid under high pressure supplied via pipeline 8 is expanded into the first, or high pressure, separator 2 via a throttle valve 10. The high pressure separator generally separates three phases; water and solids such as sand which settle in the base of the separator and are removed via pipeline 12 and valve 14; liquid hydrocarbons which are recovered in pipeline 16, expanded in a throttle valve 18 and then fed into the second, or medium pressure, separator 4 and high pressure gas which is drawn off through pipeline 20 and valve 22.
In the medium pressure separator 4 medium pressure gas is withdrawn through pipeline 24 and valve 26 and liquid is withdrawn through pipeline 28, expanded in throttle valve 30 and fed into the third, or low pressure, separator 6 from which low pressure gas is removed through pipeline 32 and valve 34 and liquid at the desired vapor pressure is recovered via pipeline 36 and valve 38.
Flash separation as shown does not give as good a separation of gas and liquids as the aforementioned distillation plus oil wash. Increasing the number of flash separation stages provides an improvement in separation where liquid of a given vapor pressure is required as the end product but in general the use of more than four stages is not considered to be economic.
The gas from the high pressure separator 2 is relatively lean in higher boiling components such as propane, butane and heavier hydrocarbons and is furthermore generally at a sufficiently high pressure to be used e.g. as a gas turbine fuel without further pressurization. The gases from the medium and low pressure stages contain increasing concentrations of higher boiling components and are at lower pressures which are generally too low for the gases to be usable without recompression. The higher boiling components in these lower pressure gas streams represent a loss of valuable hydrocarbons which could be contained in the liquid if a better method of separation could be devised and if the liquid contained a lower percentage of the very light hydrocarbons such as propane, ethane and methane which have an increasing effect on the vapor pressure of the liquid per unit percent that they are present in the liquid. However, for use in remote locations on land or in off-shore locations any such improvement must be achieved without substantial increase in the complexity or cost of the plant.